Chelating agents and scale inhibitors in degradable downhole tools

ABSTRACT

Downhole tools, methods, and systems related thereto. An example downhole tool includes a body comprising a degradable core and a chelating agent or a chelating agent/scale inhibitor mixture integrated therein. The chelating agent and scale inhibitors help to direct and control the degradation of the degradable core.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. application Ser. No.15/106,435, filed Jun. 20, 2016, which is the National Phase Entry ofPCT/US2016/015885, titled “Downhole Tools Comprising Sealing Elementscomposed of Elastomer and Anhydrous Acid Particles,” filed Feb. 1, 2016,which is a continuation-in-part of PCT/US2015/067286, titled “DownholeTools Comprising Aqueous-Degradable Sealing Elements of ThermoplasticRubber,” and filed Dec. 22, 2015. PCT/US2015/067286 is acontinuation-in-part of both PCT/US2015/035823, titled “Downhole ToolsComprising Aqueous-Degradable Elastomer Sealing Elements withCarbodiimide,” filed Jun. 15, 2015, and PCT/US2015/035812, titled“Downhole Tools Comprising Cast Degradable Sealing Elements,” and filedJun. 15, 2015. PCT/US2015/035823 and PCT/US2015/035812 are eachcontinuations-in-part of PCT/US2014/045535, titled “Downhole ToolsComprising Aqueous-Degradable Sealing Elements,” filed Jul. 7, 2014.

BACKGROUND

The present disclosure generally relates to degradable downhole toolscomprising chelating agents, and more specifically, to downhole toolscomprising a degradable core and a chelating agent integrated into thedownhole tool.

A variety of downhole tools are within a wellbore in connection withproducing or reworking a hydrocarbon bearing subterranean formation. Thedownhole tool may comprise a wellbore zonal isolation device capable offluidly sealing two sections of the wellbore from one another andmaintaining differential pressure (i.e., to isolate one pressure zonefrom another). The wellbore zonal isolation device may be used in directcontact with the formation face of the wellbore, with casing string,with a screen or wire mesh, and the like.

After the production or reworking operation is complete, the seal formedby the downhole tool must be broken and the tool itself removed from thewellbore. The downhole tool must be removed to allow for production orfurther operations to proceed without being hindered by the presence ofthe downhole tool. Removal of the downhole tool(s) is traditionallyaccomplished by complex retrieval operations involving milling ordrilling the downhole tool for mechanical retrieval. In order tofacilitate such operations, downhole tools have traditionally beencomposed of drillable metal materials, such as cast iron, brass, oraluminum. These operations can be costly and time consuming, as theyinvolve introducing a tool string (e.g., a mechanical connection to thesurface) into the wellbore, milling or drilling out the downhole tool(e.g., at least breaking the seal), and mechanically retrieving thedownhole tool or pieces thereof from the wellbore to bring to thesurface.

To reduce the cost and time required to mill or drill a downhole toolfrom a wellbore for its removal, degradable downhole tools have beendeveloped. The degradable materials that have been proposed for use informing a downhole tool body are often highly brittle, and can formrock-like solids upon degradation that will cause plugging and stoppageproblems in the removal of the downhole tool. Designs and compositionsare needed which can help control and direct distribution and productionof the byproducts during degradation of a downhole tool and therebyeliminate the propensity for forming plugs.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of theembodiments, and should not be viewed as exclusive embodiments. Thesubject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIG. 1 illustrates a cross-sectional view of a well system comprising adownhole tool, according to one or more embodiments described herein.

FIG. 2 depicts an enlarged cross-sectional view of a downhole tool,according to one or more embodiments described herein.

FIG. 3 depicts an enlarged cross-sectional view of a downhole tool,according to one or more embodiments described herein.

FIG. 4 shows an enlarged cross-sectional view of a downhole tool,according to one or more embodiments described herein.

FIG. 5 shows the degradation of an elastomer comprising various amountsof citric acid particles after three (3) days of incubation in tap waterat 150° F.

FIG. 6 shows the degradation of an elastomer comprising various amountsof citric acid particles after four (4) days of incubation in tap waterat 116° F.

FIG. 7 is a photograph of five experimental samples of degradablematerial at the beginning of the degradation experiment described inExample 3 herein.

FIG. 8 is a photograph of the five experimental samples of degradablematerial described in Example 3 after exposure to a brine for 18 hoursat 200° F. for 18 hours.

DETAILED DESCRIPTION

The present disclosure generally relates to degradable downhole toolscomprising chelating agents, and more specifically, to downhole toolscomprising a degradable core and a chelating agent integrated into thedownhole tool. The downhole tool may have various setting mechanisms forfluidly sealing the two sections of the wellbore with the sealingelement including, but not limited to, hydraulic setting, mechanicalsetting, setting by swelling, setting by inflation, and the like. Thedownhole tool may be a wellbore isolation device, such as a frac plug, abridge plug, a packer, a wiper plug, a cement plug, or any other toolrequiring a sealing element for use in a downhole operation. Suchdownhole operations may include, but are not limited to, any type offluid injection operation (e.g., a stimulation/fracturing operation, apinpoint acid stimulation, casing repair, and the like), and the like.In some embodiments, a downhole tool is provided comprising a bodycomprising a degradable core; and a chelating agent integrated into thedownhole tool. The presence of the chelating agent integrated into thedownhole tool assists in controlling the production and distribution ofone or more degradation products of the degradable core. In this regard,the chelating agent can control, and in some instances substantiallyprevent or completely prevent, the formation of rock-like byproducts,large particulates, aggregates, or plugs during the degradation processof the degradable core. Thus, the use of a chelating agent integratedinto a downhole tool significantly reduces the consolidation ofdegradation byproducts to an amount less than would be expected in theabsence of such a chelating agent. This control, prevention, andreduction benefit can be further enhanced by the combination of a scaleinhibitor with the chelating agent.

In some embodiments, the chelating agent is integrated into the downholetool as a layer around the degradable core. In some embodiments, thechelating agent is integrated as a liner on an inner diameter of thedegradable core. In some embodiments, the chelating agent is integratedonto the downhole tool as an appendage, for example a dongle, extendingdownward from a bottom portion of the downhole tool. In someembodiments, the chelating agent is present as a component of thedegradable material of the degradable core. In this configuration, thechelating agent can be manufactured into the degradable core. In any ofthe above embodiments, a scale inhibitor can be combined with thechelating agent and incorporated as a combined chelating agent and scaleinhibitor composition into the downhole tool. In some embodiments, thechelating agent or the chelating agent/scale inhibitor composition canbe integrated into the downhole tool in any combination of the aboveembodiments of a layer, a liner, an appendage, or as part of thedegradable material itself. The manner of integrating a chelating agentor a chelating agent/scale inhibitor composition will be readilyapparent to one of skill in the art. For example, the chelating agent orchelating agent/scale inhibitor mixture can be mixed into the castingprocess of a dissolvable metal alloy, for example in a solid solutionprocessing. In another example, in a powder metallurgy process, thechelating agent or chelating agent/scale inhibitor mixture can besintered with metal alloys.

The chelating agent can function to form a chelate complex with one ormore degradation components of the degradable core. The term “chelatingagent” as used herein, includes within the definition chelating agent,complexing agent, or coordinating agent. A chelate complex exists when asingle ion or charged microparticle (e.g., a metallic ion, a metaloxide, etc.) forms complexation or coordination bonds with a polydentateligand. A ligand is commonly called a chelant, chelating agent orsequestering agent. The ligand sequesters and inactivates the centralion so the ion does not easily react with other elements or ions toproduce precipitates or scale. A polydentate ligand is a molecule orcompound in which at least two atoms of the ligand bond with the ion. Apolydentate ligand can be, for example, bidentate (2 atoms bond),tridentate (3 atoms bond), tetradentate (4 atoms bond), pentadentate (5atoms bond), and so on. A monodentate ligand is a molecule or compoundin which only one atom of the ligand bonds with the ion. The ligand canalso contain at least one functional group that is capable of forming abond with the chelant. Common functional groups include a carboxylate,an amine, an alcohol, or an ether.

Suitable chelating agents will be readily apparent to a person ofordinary skill in the art. In general, the optimal choice for achelating agent will be determined by a combination of the chelatingagent's solubility and the desired volumetric efficiency. In someembodiments, the chelating agent comprises a solid, an anhydrous, apartially hydrated, or a fully hydrated material. In some embodiments,the chelating agent is anhydrous. In some embodiments, the chelatingagent comprises a functional group that forms one or more complexationor coordination bonds with a byproduct of degradation of the degradablecore. In some embodiments, the functional group has at least oneavailable charge for bonding with a degradation byproduct. In someembodiments, the functional group of the chelating agent can be selectedfrom the group consisting of, a carboxylate; an amine; an alcohol; anether; a phosphate; a thiol; a thiol ether; isocyanate; isothiocyanate;cyclopentadienide; a group containing an element selected fromphosphorus, sulfur, nitrogen, and oxygen; and combinations thereof.Examples of suitable chelating agents include, but are not limited to,polyaminocarboxylic acids and salts, aminopolyethers, multicarboxylicacids, aminophosphonates, polyaminoacids, ethylenediaminetetraaceticacid (EDTA), disodium EDTA (Na₂EDTA),hydroxyethylethylenediaminetriacetic acid (HEDTA), docosatetraenoic acid(DTA), nitrilotriacetic acid (NTA), hydroxyaminopolycarboxylic acid(HACA), diethylenetriaminepentaacetic acid (DTPA),hydroxyethyliminodiacetic acid (HEIDA), or polyaspartic acid (PASP) andthe like, or combinations thereof. In some embodiments, the chelatingagent is selected from the group consisting of acetic acid, citric acid,lactic acid, succinic acid, maleic acid, a phosphonate, EDTA, Na₂EDTA,HEDTA, DTA, NTA, HACA, DTPA, HEIDA, polyasparctic acid, methylglycinediacetic acid (MGDA), N-tris[(1,2-dicarboxyethoxy)ethyl]amine (TCA6),N-bis[2-(carboxymethoxy)ethyl]glycine (BCA3),N-bis[2-(1,2-dicarboxyethoxy)ethyl]glycine (BCA5),N-bis[2-(1,2-dicarboxyethoxy)ethyl]aspartic acid (BCA6),N-bis[2-(methylcarboxymethoxy)ethyl]glycine (MBCA3),N-bis[2-(1,2-dicarboxyethoxy)ethyl]methylglycine (MBCA5), Beta-Alaninediacetic acid (B-ADA), ethylenediaminedisuccinic acid (EDDS) glutamicacid diacetic acid (GLDA), hydroxyiminodisuccinic acid (HIDS),hydroxyethylenediaminetriacetic acid, and combinations thereof.

The chelating agent can be present in any suitable amount. The amountused will depend upon several factors, including the specific chelatingagent, the composition of the degradable core material, the temperatureof a wellbore environment, the composition of any subterranean fluids,wellbore environment (e.g, volume, subterranean composition, etc.), andthe manner in which the chelating agent is integrated. In someembodiments, the chelating agent is present in a weight ratio ofchelating agent to degradable material in a range from a lower amount ofabout 1:6, 1:5, 1:4, 1:3, or 1:2 to an upper amount of about 1:1, 1:2,1:3, or 1:4; In some embodiments the weight ratio of chelating agent todegradable material is 1:4. In some embodiments, the weight ratio ofchelating agent to degradable material is 1:2.

A scale inhibitor is a class of chemicals that are used to slow orprevent scaling in fluid systems. In petroleum and subterraneanoperations, scaling is the precipitation and accumulation of insolublecrystals, creating solid deposits that grow over time. Suitable scaleinhibitors will be readily apparent to a person of ordinary skill in theart and include, but are not limited to phosphonate compounds, forexample, nitrilotris(methylenephosphonic acid) (NTMP), ethylenediaminetetra(methylene phosphonic acid) (EDTMP), anddiethylenetriaminepentakis(methylphosphonic acid) (DTPMP). Other scaleinhibitors include acrylic acid polymers; maleic acid polymers; PBTC(phosphonobutane-1,2,4-tricarboxylic acid); ATMP (amino-trimethylenephosphonic acid); HEDP (1-hydroxyethylidene-1,1-diphosphonic acid),polyacrylic acid (PAA), phosphinopolyacrylates (such as PPCA);polymaleic acids (PMA); maleic acid terpolymers (MAT); sulfonic acidcopolymers, such as SPOCA (sulfonated phosphonocarboxylic acid);polyvinyl sulfonates; and Poly-Phosphono Carboxylic acid (PPCA). Oneadvantage in using phosphonates over a phosphonic acid is higher watersolubility.

The scale inhibitor can be present in any suitable amount. The amount ofscale inhibitor will vary and can depend on several factors includingthe specific chelating agent, the specific degradable core material,temperature, subterranean fluid composition, wellbore environment (e.g,volume, subterranean composition, etc.), and the manner in which thechelating agent/scale inhibitor mixture is integrated into the downholetool. In some embodiments, the ratio of chelating agent to scaleinhibitor on a weight/weight basis can be in the range of from a loweramount of about 1:1, 2:1, 3:1, 4:1 or 5:1 to an upper amount of about6:1, 5:1, 4:1, 3:1, or 2:1. In some embodiments, the ratio of chelatingagent to scale inhibitor is in the range of about 6:1 to about 1:1.

In some embodiments, the chelating agent or chelating agent/scaleinhibitor composition can further include a degradable binder. Thebinder aids in giving structural integrity to the chelating agent orchelating agent/scale inhibitor mixture. In some embodiments, the bindercan dissolve in a wellbore fluid, melt at a downhole temperature, reactin a wellbore environment.

Examples of suitable binders are known in the art and will be readilyapparent to one of skill in the art. In some embodiments, the degradablebinder is selected from the group consisting of a salt, a wax, a fusiblemetal, a polymer, a rubber, and combinations thereof.

In some embodiments, the downhole tool can further comprise at least onesealing element composed of an elastomer and anhydrous acid particles.In some embodiments, at least a portion of the sealing elementhydrolytically degrades in a wellbore environment, wherein the anhydrousacid particles are pro-acids. Such sealing elements are described indetail herein below.

In some embodiments, a method is provided comprising installing adownhole tool described herein in a wellbore; fluidly sealing twosections of the wellbore with the downhole tool; performing a downholeoperation; exposing at least a portion of the degradable core to anaqueous fluid in the wellbore environment; and hydrolytically degradingat least a portion of the degradable core in the wellbore environment,wherein integration of the chelating agent into the downhole toolcontrols the production and distribution of one or more degradationproducts of the degradable core. In some embodiments, controlling theproduction and distribution of one or more degradation productscomprises preventing consolidation of the degradation byproducts.

The anhydrous acid particles of the sealing element are hydrolyzed(which may also involve a size increase of the anhydrous acid particles)in the wellbore environment to accelerate degradation of the sealingelement. In some embodiments, all or a portion of the body is alsodegradable in the wellbore environment. In such instances, the anhydrousacid particles, once hydrolyzed, may additionally accelerate degradationof the degradable portion of the body.

As used herein, the term “degradable,” and all of its grammaticalvariants (e.g., “degrade,” “degradation,” “degrading,” and the like),refers to the dissolution or chemical conversion of materials intosmaller components, intermediates, or end products by at least one ofsolubilization, hydrolytic degradation, biologically formed entities(e.g., bacteria or enzymes), chemical reactions, thermal reactions, orreactions induced by radiation. In embodiments, the sealing elements anddegradable core (i.e., body 210 described herein) of the presentdisclosure degrade by hydrolytic degradation. The term “at least aportion” with reference to degradation (e.g., “at least a portion of thesealing element is degradable” or “at least a portion of the body isdegradable,” or “at least a portion of the sealing element ishydrolytically degradable,” and grammatical variants thereof) refers todegradation of at least about 80% of the volume of that part. In someinstances, the degradation of the material may be sufficient for themechanical properties of the material to reduce to a point that thematerial no longer maintains its integrity and, in essence, falls apart.The conditions for degradation are generally wellbore conditions wherean external stimulus may be used to initiate or affect the rate ofdegradation. For example, the embodiments of the present disclosureemploy sealing elements comprising anhydrous acid particles thataccelerate degradation of at least the sealing element and, in someinstances, other portions of the downhole tool composed of a degradablematerial. The term “wellbore environment” includes both naturallyoccurring wellbore environments and introduced materials into thewellbore.

In some embodiments, the downhole tool includes a sealing elementcomposed of an elastomer (including one or more elastomers) andanhydrous acid particles. The sealing element is capable of fluidlysealing two sections of a wellbore (which may be also referred to as“setting” the downhole tool). In some embodiments, the downhole tool maycomprise a body and at least one sealing element composed of anelastomer and anhydrous acid particles. The sealing element degrades ina wellbore environment, such as upon contact with an aqueous fluidtherein. As discussed in detail below, degradation of the sealingelement may be accelerated, rapid, or normal, degrading anywhere fromabout 2 hours to about 120 days from first contact with a stimulus inthe wellbore environment (e.g., an aqueous fluid), wherein degradationis further accelerated due to the presence of the anhydrous acidparticles.

In some embodiments, the elastomer forming the sealing element isaqueous-degradable and degradation is in an aqueous fluid wellboreenvironment. The anhydrous acid particles are hydrolyzed upon contactwith the aqueous fluid wellbore environment and form an acid (e.g.,hydrolysis of anhydrous citric acid, or hydrolysis of maleic anhydrideto generate maleic acid). The acid further accelerates hydrolyticdegradation of the aqueous-degradable elastomer forming a portion of thesealing element. While the present disclosure focuses on hydrolyticdegradation of the sealing elements described herein in an aqueous fluidwellbore environment, it will be appreciated that the elastomer formingthe sealing element may be oil-degradable (e.g., in the presence of ahydrocarbon wellbore environment) and the presence of the anhydrous acidparticles will also accelerate degradation of the oil-degradableelastomer. For example, the elastomer (e.g., a urethane elastomer) canbreak down into its monomeric units that are soluble in a hydrocarbon(i.e., oil). This solubility can drive the equilibrium of thedegradation of the elastomer. In essence, the degraded elastomerproducts are favored in the K_(eq) (equilibrium constant) of thedegradation mechanism and, thus, helps push the degradation process inthe forward direction. Degradation of the elastomer forming the sealingelement may additionally be achieved or otherwise affected (e.g., inaddition to hydrolytic degradation or degradation by an acid) byelevated temperature, salinity (or pH) of a fluid contacting theelastomer, and any combination thereof.

In some embodiments, at least a portion of the body itself may also bedegradable upon exposure to the wellbore environment. The embodimentsherein permit fluid sealing of two wellbore sections with a downholetool having a sealing element that later degrades in situ, where suchdegradation is accelerated by the presence of anhydrous acid particles,preferably without the need to mill or drill and retrieve the downholetool from the wellbore. Moreover, the propensity of the degradationbyproducts to form rock-like solids and/or plugs is significantlydecreased or altogether removed by the integration of chelating agentsand scale inhibitors as described herein above. In particular, thedegradation of the sealing element results in failure of the sealingelement to maintain differential pressure and form an effective seal. Insuch cases, the downhole tool may drop into a rathole in the wellborewithout the need for retrieval or may be sufficiently degraded in thewellbore so as to be generally indiscernible. It will be appreciated byone of skill in the art that while the embodiments herein are describedwith reference to a downhole tool, the sealing elements composed of anelastomer and anhydrous acid particles disclosed herein may be used withany wellbore operation equipment that may preferentially degrade uponexposure to a stimuli, such as aqueous fluids, and where accelerateddegradation is desirable (i.e., by the anhydrous acid particles).

One or more illustrative embodiments disclosed herein are presentedbelow. Not all features of an actual implementation are described orshown in this application for the sake of clarity. It is understood thatin the development of an actual embodiment incorporating the embodimentsdisclosed herein, numerous implementation-specific decisions must bemade to achieve the developer's goals, such as compliance withsystem-related, lithology-related, business-related, government-related,and other constraints, which vary by implementation and from time totime. While a developer's efforts might be complex and time-consuming,such efforts would be, nevertheless, a routine undertaking for those ofordinary skill in the art having benefit of this disclosure.

It should be noted that when “about” is provided herein at the beginningof a numerical list, the term modifies each number of the numericallist. In some numerical listings of ranges, some lower limits listed maybe greater than some upper limits listed. One skilled in the art willrecognize that the selected subset will require the selection of anupper limit in excess of the selected lower limit. Unless otherwiseindicated, all numbers expressed in the present specification andassociated claims are to be understood as being modified in allinstances by the term “about.” As used herein, the term “about”encompasses +/−5% of a numerical value. For example, if the numericalvalue is “about 80%,” then it can be 80%+/−5%, equivalent to 76% to 84%.Accordingly, unless indicated to the contrary, the numerical parametersset forth in the following specification and attached claims areapproximations that may vary depending upon the desired propertiessought to be obtained by the exemplary embodiments described herein. Atthe very least, and not as an attempt to limit the application of thedoctrine of equivalents to the scope of the claim, each numericalparameter should at least be construed in light of the number ofreported significant digits and by applying ordinary roundingtechniques.

While compositions and methods are described herein in terms of“comprising” various components or steps, the compositions and methodscan also “consist essentially of” or “consist of” the various componentsand steps. When “comprising” is used in a claim, it is open-ended.

As used herein, the term “substantially” means largely, but notnecessarily wholly.

The use of directional terms such as above, below, upper, lower, upward,downward, left, right, uphole, downhole and the like are used inrelation to the illustrative embodiments as they are depicted in thefigures, the upward direction being toward the top of the correspondingfigure and the downward direction being toward the bottom of thecorresponding figure, the uphole direction being toward the surface ofthe well and the downhole direction being toward the toe of the well.

Referring now to FIG. 1, illustrated is an exemplary well system 110 fora downhole tool 100. As depicted, a derrick 112 with a rig floor 114 ispositioned on the earth's surface 105. A wellbore 120 is positionedbelow the derrick 112 and the rig floor 114 and extends intosubterranean formation 115. As shown, the wellbore may be lined withcasing 125 that is cemented into place with cement 127. It will beappreciated that although FIG. 1 depicts the wellbore 120 having acasing 125 being cemented into place with cement 127, the wellbore 120may be wholly or partially cased and wholly or partially cemented (i.e.,the casing wholly or partially spans the wellbore and may or may not bewholly or partially cemented in place), without departing from the scopeof the present disclosure. Moreover, the wellbore 120 may be anopen-hole wellbore. A tool string 118 extends from the derrick 112 andthe rig floor 114 downwardly into the wellbore 120. The tool string 118may be any mechanical connection to the surface, such as, for example,wireline, slickline, jointed pipe, or coiled tubing. As depicted, thetool string 118 suspends the downhole tool 100 for placement into thewellbore 120 at a desired location to perform a specific downholeoperation. In some embodiments, the downhole tool 100 is connected tothe tool string 118 via a means such as physical connection, or aconnection using one or more portions of the downhole tool 100 (e.g.,components of the body, such as slips, wedges, and the like, or thesealing element). That is, the tool string 118 may be tubing inside ofthe casing string 125 (or the wellbore 120 if casing string is not used)and the downhole tool 100 may be hydraulically pumped or gravitationallyplaced therein where the connection between the tool string 118 and thedownhole tool 100 is due to pressure contact (e.g., slips, wedges,sealing element, and the like) between the downhole tool 100 and theinterior of the tool string 118. In some instances, the tool string 118and the casing string 125 are one and the same (i.e., the casing stringis a type of tool string), and the downhole tool 100 is connected to theinner diameter (e.g., the pressure contact described below) thereto. Aspreviously mentioned, the downhole tool 100 may be any type of wellborezonal isolation device including, but not limited to, a frac plug, abridge plug, a packer, a wiper plug, or a cement plug.

It will be appreciated by one of skill in the art that the well system110 of FIG. 1 is merely one example of a wide variety of well systems inwhich the principles of the present disclosure may be utilized.Accordingly, it will be appreciated that the principles of thisdisclosure are not necessarily limited to any of the details of thedepicted well system 110, or the various components thereof, depicted inthe drawings or otherwise described herein. For example, it is notnecessary in keeping with the principles of this disclosure for thewellbore 120 to include a generally vertical cased section. The wellsystem 110 may equally be employed in vertical, horizontal, and/ordeviated (i.e., slanted from true vertical or true horizontal)wellbores, without departing from the scope of the present disclosure.Furthermore, it is not necessary for a single downhole tool 100 to besuspended from or otherwise connected to the tool string 118.

In addition, it is not necessary for the downhole tool 100 to be loweredinto the wellbore 120 using the derrick 112. Rather, any other type ofdevice suitable for lowering the downhole tool 100 into the wellbore 120for placement at a desired location may be utilized without departingfrom the scope of the present disclosure such as, for example, mobileworkover rigs, well servicing units, and the like. Although notdepicted, the downhole tool 100 may alternatively be hydraulicallypumped into the wellbore and, thus, not need the tool string 118 fordelivery into the wellbore 120, although the downhole tool 100 may beotherwise connected to (i.e., in contact with) a tool string 118 locatedwithin the wellbore 120.

Although not depicted, the structure of the downhole tool 100 may takeon a variety of forms to provide fluid sealing between two wellboresections. The downhole tool 100, regardless of its specific structure asa specific type of wellbore zonal isolation device, comprises a body anda degradable core. The downhole tool may further comprise a sealingelement. Both the body and the sealing element may each be composed ofthe same material (i.e., all or a portion of the body may be composed ofthe elastomer and anhydrous acid particles described herein, and anyother additives). Generally, however, the body provides structuralrigidity and other mechanical features to the downhole tool 100 and thesealing element is a resilient (i.e., elastic) material capable ofproviding a fluid seal between two sections of the wellbore 120.

Referring now to FIG. 2, with continued reference to FIG. 1, onespecific type of downhole tool described herein is a frac plug wellborezonal isolation device for use during a well stimulation/fracturingoperation. FIG. 2 illustrates a cross-sectional view of an exemplaryfrac plug 200 being lowered into a wellbore 120 on a tool string 118. Aspreviously mentioned, the frac plug 200 generally comprises a body 210and, in some embodiments, a sealing element 285. The body 210 comprisesa plurality of components, as described below. As used herein, the term“components,” and grammatical variants thereof, with reference to thebody 210 refers to any structure (e.g., functional structure) in contactwith the body 210 that is not the sealing element 285. In someembodiments, the sealing element 285 may be resilient and have a Shore Adurometer hardness in an amount of from about 60 to about 100,encompassing any value and subset therebetween. For example, the sealingelement 285 may have a Shore A durometer hardness in an amount of fromabout 70 to about 90, or of from about 70 to about 80, or from about 75to about 85, encompassing any value and subset therebetween. Forexample, in some embodiments, the sealing element 285 may be resilientand have a Shore A durometer hardness of from about 75 to about 95. Eachof these values is critical to the embodiments of the present disclosureand may depend on a number of factors including, but not limited to, thematerial selected to form the sealing element 285, the operation to beperformed by the downhole tool 100 (FIG. 1), the type of downhole tool100, and the like.

The sealing element 285, as depicted, comprises an upper sealing element232, a center sealing element 234, and a lower sealing element 236. Itwill be appreciated that although the sealing element 285 is shown ashaving three portions (i.e., the upper sealing element 232, the centersealing element 234, and the lower sealing element 236), any othernumber of portions, or a single portion, may also be employed withoutdeparting from the scope of the present disclosure.

As depicted, the sealing element 285 is extending around the body 210;however, it may be of any other configuration suitable for allowing thesealing element 285 to form a fluid seal in the wellbore 120, withoutdeparting from the scope of the present disclosure. For example, in someembodiments, the body may comprise two sections joined together by thesealing element, such that the two sections of the body compress topermit the sealing element to make a fluid seal in the wellbore 120.Other such configurations are also suitable for use in the embodimentsdescribed herein. Moreover, although the sealing element 285 is depictedas located in a center section of the body 210, it will be appreciatedthat it may be located at any location along the length of the body 210,without departing from the scope of the present disclosure.

The body 210 of the frac plug 200 comprises an axial flowbore 205extending therethrough. A cage 220 is formed at the upper end of thebody 210 for retaining a ball 225 that acts as a one-way check valve. Inparticular, the ball 225 seals off the flowbore 205 to prevent flowdownwardly therethrough, but permits flow upwardly through the flowbore205. One or more slips 240 are mounted around the body 210 below thesealing element 285. The slips 240 are guided by a mechanical slip body245. A tapered shoe 250 is provided at the lower end of the body 210 forguiding and protecting the frac plug 200 as it is lowered into thewellbore 120. An optional enclosure 275 for storing a chemical solutionmay also be mounted on the body 210 or may be formed integrally therein.In one embodiment, the enclosure 275 is formed of a frangible material.

In FIG. 3, a view of downhole tool 100 is depicted showing variousconfigurations (301, 310, 315, and 320) of a chelating agent orchelating agent/scale inhibitor mixture as integrated into the downholetool 100. Although each of these configurations is shown in FIG. 3, itis not necessary that a downhole tool consist of all theseconfigurations. Rather, a downhole tool can have a single configuration,two configuration, three configurations, or all four configurations. Inconfiguration 301, a chelating agent or a chelating agent/scaleinhibitor mixture is present as a coating on or around body 210. Inconfiguration 310, a chelating agent or a chelating agent/scaleinhibitor mixture is manufactured into the degradable material of body210. In configuration 315, a liner of chelating agent or chelatingagent/scale inhibitor mixture surrounds body 210. The liner can be indirect contact with the degradable core along the entirety of body 210,a portion thereof, or can be spaced apart from body 210. In someembodiments, the liner 315, is attached to an inner diameter of body210. In configuration 320, a chelating agent or chelating agent/scaleinhibitor mixture is present as appendage. The appendage can be a dongleor other solid component. In some embodiments, the appendage is attachedat a bottom portion of the downhole tool 100 and extends in a downwarddirection. In some embodiments the appendage 320, is in contact with abottom portion of the degradable core of body 210, and projects downwardtherefrom. In any of the configurations of FIG. 3, the chelating agentor chelating agent/scale inhibitor mixture can be further combined witha degradable binder as described herein above to provide structuralintegrity in the manufacture thereof.

The sealing element 285 of the downhole tool 100 is composed of anelastomer and anhydrous acid particles. At least a portion of thesealing element 285 is hydrolytically degradable in a wellboreenvironment, and in some embodiments at least a portion of the body 210(e.g., one or more components of the body 210) is also hydrolyticallydegradable in a wellbore environment. As used herein, the term“hydrolytic degradation” refers to the degradation of a material bycleavage of chemical bonds in the presence (e.g., by the addition of, orupon contact with) an aqueous fluid. The portion of the sealing element285 (or the portion of the body 210) that is hydrolytically degradableat least partially degrades in the presence of an aqueous fluid in awellbore environment, such as preexisting aqueous fluids therein orintroduced aqueous fluid (e.g., by a wellbore operator or wellboreequipment). Thus, the elastomer described herein may wholly degrade orpartially degrade; however, as applicable to the sealing element 285,the amount of degradation is capable of causing the sealing element 285to no longer maintain a fluid seal in the wellbore capable ofmaintaining differential pressure. The aqueous fluid that may degradethe elastomer or the degradable core includes, but is not limited to,fresh water, saltwater (e.g., water containing one or more saltsdissolved therein), brine (e.g., saturated salt water), seawater,produced water, wastewater (either treated or untreated), mud(water-based mud or oil-based mud), or combinations thereof.

The hydrolytic degradation of the elastomer forming at least a portionof the sealing element 285 and/or the degradation of any degradableportion of the body 210 (including where the portion of the body 210 isformed from an elastomer as described herein) may be by a number ofmechanisms. For example, the degradation may be by swelling, dissolving,undergoing a chemical change, undergoing thermal degradation incombination with any of the foregoing, and any combination thereof.Degradation by swell involves the absorption by the elastomer or otherdegradable material of a fluid (e.g., an aqueous fluid) in the wellboreenvironment such that the mechanical properties of the elastomer ormaterial degrade. That is, the elastomer or degradable materialcontinues to absorb the fluid until its mechanical properties are nolonger capable of maintaining the integrity of the elastomer ordegradable material at least partially falls apart. In some embodiments,the elastomer or other degradable material may be designed to onlypartially degrade by swelling in order to ensure that the mechanicalproperties of the sealing element 285 and/or body 210 formed from theelastomer or other degradable material is sufficiently capable oflasting for the duration of the specific operation in which it isutilized (e.g., of maintaining a seal). Degradation by dissolvinginvolves use of an elastomer or other degradable material that issoluble or otherwise susceptible to fluids (e.g., aqueous fluids), suchthat the fluid is not necessarily incorporated into the elastomer ordegradable material (as is the case with degradation by swelling), butbecomes soluble upon contact with the fluid. Degradation by undergoing achemical change may involve breaking the bonds of the backbone of theelastomer polymer (e.g., polymer backbone) or degradable material, orcausing the bonds of the elastomer or degradable material to crosslink,such that it becomes brittle and breaks into small pieces upon contactwith even small forces expected in the wellbore environment. Thermaldegradation involves a chemical decomposition due to heat, such as theheat present in a wellbore environment. Thermal degradation of someelastomers and/or degradable materials described herein may occur atwellbore environment temperatures of greater than about 50° C. (or about120° F.). Thermal degradation may work in concert with one or more ofthe other degradation methods described herein. Accordingly, the use ofthe anhydrous acid particles to accelerate degradation of the elastomercan be used to affect degradation even at wellbore environmenttemperatures less than what would initiate thermal degradation.Combinations of any of the aforementioned degradation methods may occurfor any given elastomer and/or degradable material for use in formingall or a portion of the downhole tools described herein.

The degradation rate of the elastomer forming the sealing element 285may be accelerated, rapid, or normal, as defined herein. Rapiddegradation may be in the range of from about 2 hours to about 36 hours,encompassing any value or subset therebetween. Normal degradation may bein the range of from about 36 hours to about 14 days, encompassing anyvalue or subset therebetween. Extended degradation may be in the rangeof from about 14 days to about 120 days, encompassing any value orsubset therebetween. Accordingly, the degradation may be of from about120 minutes to about 120 days, or about 2 hours to about 36 hours, orabout 36 hours to about 14 days, or about 14 days to about 120 days,encompassing any value and subset therebetween. Each of these values iscritical and depends on a number of factors including, but not limitedto, the type of elastomer selected, the conditions of the wellboreenvironment, the amount of contact with an aqueous fluid, the type andamount of anhydrous acid particles included in the sealing element 285,and the like. It is to be appreciated that these degradation rates areaccelerated by inclusion of the anhydrous acid particles describedherein upon their hydrolysis, as described herein.

The elastomer forming a portion of the sealing element 285 (and/or oneor more portions of the body 210, if applicable) described herein may bea material that is resilient (i.e., elastic) and is at least partiallyhydrolytically degradable in a wellbore environment, and whosedegradation is accelerated upon exposure to an acid (e.g., uponhydrolyzing the anhydrous acid particles forming a portion of thesealing element 285). Accordingly, as stated above, any of theelastomers, elastomer combinations, elastomer additives (including theanhydrous acid particles), and combinations thereof described hereinwith reference to the sealing element 285 may be used to form one ormore portions of the body 210, without departing from the scope of thepresent disclosure, and without limitation.

In some embodiments, the elastomer is a material that comprises esterlinkages and wherein hydrolytic degradation of the elastomer occurs bydegradation of the ester linkages. Suitable examples of elastomers forforming a portion of the sealing element 285 include, but are notlimited to, a polyurethane rubber (e.g., cast polyurethanes,thermoplastic polyurethanes, polyethane polyurethanes), apolyester-based polyurethane rubber (e.g., lactone polyester-basedthermoplastic polyurethanes), a polyether-based polyurethane rubber, athiol-based rubber, a hyaluronic acid rubber, a hydroxybutyrate rubber,a polyester elastomer (e.g., polyether/ester copolymers, polyester/estercopolymers, and the like), a polyester amide elastomer, a polyamideelastomer, a starch-based resin (e.g., starch-poly(ethylene-co-vinylalcohol), starch-polyvinyl alcohol, starch-polylactic acid,starch-polycaprolactone, starch-poly(butylene succinate), and the like),a polyethylene terephthalate polymer, a polybutylene terephthalatepolymer, a polylactic acid polymer, a polybutylene succinate polymer, apolybutylene succinate polymer, a polyhydroxy alkanoic acid polymer, anacrylate-based polymer, a blend of chlorobutadiene rubber/reactiveclay/crosslinked sodium polyacrylate, a polystyrene polymer, acellulose-based rubber (e.g., carboxy methyl cellulose), a polyethyleneglycol-based hydrogel, a silicone-based hydrogel, a polyacrylamide-basedhydrogel, a polymacon-based hydrogel, copolymers thereof, terpolymersthereof, and any combination thereof.

In some embodiments, the elastomer(s) selected for use in forming theportion of the sealing element 285 described herein is a polyurethanerubber, a polyester-based polyurethane rubber, a polyether-basedpolyurethane rubber, and any combination thereof (collectively simply“polyurethane-based rubbers). These polyurethane-based rubbers degradein water through a hydrolytic reaction, although other degradationmethods may also affect the degradability of the polyurethane-basedrubbers, including exposure to the hydrolyzed anhydrous acid particlesdescribed herein. Polyurethane-based rubbers traditionally are formed byreacting a polyisocyanate with a polyol. In the embodiments describedherein, although non-limiting, the polyol for forming apolyurethane-based rubber may be a natural oil polyol, a polyesterpolyol (e.g., polybutadienes (e.g., polybutanediol adipate),polycaprolactones, polycarbonates, and the like), or a polyether polyol(e.g., polytetramethylene ether glycol, polyoxypropylene-glycol,polyoxyethylene glycol, and the like). In some embodiments, polyesterpolyols are preferred, as they are more readily degradable upon contactwith an aqueous fluid. However, any polyol may be used to form thepolyurethane-based rubber for use as the elastomer described herein, andeach is critical to the disclosed embodiments, as the amount of desireddegradation over time may depend on a number of factors including theconditions of the subterranean formation, the subterranean formationoperation being performed, and the like. Indeed, because the sealingelement 285 additionally includes anhydrous acid particles, theresultant acid upon hydrolyzing the anhydrous acid particles assistswith degradation. Combinations of these polyols may also be used,without departing from the scope of the present disclosure.

Accordingly, the rate of hydrolytic degradation of a polyurethane-basedrubber for use as the elastomers described herein may be adjusted andcontrolled based on the order of the polyol addition, as well as thepolyol properties and quantities. As an example, in some embodiments,the amount of polyol is included in an amount of from about 0.25 toabout 2 of the polyisocyanate in the polyurethane-based rubber,encompassing any value and subset therebetween. For example, the amountof polyol included may be in an amount in the range of from about 0.25to about 1.75, or about 0.5 to about 1.5, or about 0.75 to about 1stoichiometric ratio of the polyisocyanate in the polyurethane-basedrubber, encompassing any value and subset therebetween. The amount ofpolyol included is bound by stoichiometry of the polymerization perchemical reaction. Each of these values is critical to the embodimentsdescribed herein and may depend on a number of factors including, butnot limited to, the desired hydrolytic degradation rate, the type ofpolyol(s) selected, the type of subterranean operation being performed,and the like.

In some embodiments, where the elastomer selected is apolyurethane-based rubber for use in the sealing element 285, theinclusion of a low functionality initiator may be included to impartflexibility to the sealing element 285. Such low functionalityinitiators may include, but are not limited to dipropylene glycol,glycerine, sorbitol/water solution, and any combination thereof. As usedherein, the term “low functionality initiator,” and grammatical variantsthereof, refers to the average number of isocyanate reactive sites permolecule in the range of from about 1 to about 5, encompassing any valueand subset therebetween. For example, the average number of isocyanatereactive sites per molecule may be of from about 1 to about 3, or about3 to about 5, encompassing any value and subset therebetween. These lowfunctionality initiators impart flexibility to the sealing element 285and may be included in the polyurethane-based rubbers described hereinin an amount in the range of from about 1% to about 50% by weight of thepolyol in the polyurethane-based rubber, encompassing any value andsubset therebetween. For example, the polyurethane-based rubbersdescribed herein in an amount in the range of from about 1% to about10%, or about 10% to about 25%, or about 25% to about 35%, or about 35%to about 50% by weight of the polyol in the polyurethane-based rubber,encompassing any value and subset therebetween. Additionally, in someembodiments, higher molecular weight polyols for use in forming thepolyurethane-based rubbers described herein may impart flexibility tothe sealing element 285 described herein. For example, in someembodiments, the molecular weight of the selected polyols may be in therange of from about 200 Daltons (Da) to about 20000 Da, encompassing anyvalue and subset therebetween. For example, the molecular weight of theselected polyols may be in the range of from about 200 Da to about 5000Da, or about 5000 Da to about 10000 Da, or about 10000 Da to about 15000Da, or about 15000 Da to about 20000 Da, encompassing any value andsubset therebetween. Each of these values is critical to the embodimentsdescribed herein and may depend on a number of factors including, butnot limited to, the desired flexibility of the elastomer (and thus,e.g., the sealing element 285), the type of subterranean formationoperation being performed, the conditions of the wellbore environment,and the like, and any combination thereof.

In some embodiments, the selected elastomer is a polyurethane-basedrubber that further includes a curative such as toluene diisocyanate,4,4′-diphenylmethane diisocyanate, an amine curative, a polysulfidecurative, and any combination thereof. Typically, the curative used aspart of a vulcanization process for crosslinking the elastomer, and istypically present in an amount of about 0.1% to about 20% by weight ofthe polyurethane-based rubber, encompassing any value and subsettherebetween. For example, the amount of curative may be about 0.1% toabout 1%, or about 1% to about 4%, or about 4% to about 8%, or about 8%to about 12%, or about 12% to about 16%, or about 16% to about 20%, orabout 2% to about 18%, or about 4% to about 16%, or about 6% to about14%, or about 8% to about 12% by weight of the polyurethane-basedrubber, encompassing any value and subset therebetween. Each of thesevalues is critical to the embodiments described herein and depend on anumber of factors including, but not limited to, the selectedpolyurethane-based rubber (e.g., the polyester-based polyurethanerubber), the selected curative, other additives included in theelastomer, the process for forming the elastomer, and the like, and anycombination thereof.

In other embodiments, the elastomer described herein may be formed froma thiol-based polymer. As used herein, the term “thiol” is equivalent tothe term “sulfhydryl.” The thiol-based polymer comprises at least onethiol functional group. In some embodiments, the thiol-based polymer maycomprise thiol functional groups in the range of from about 1 to about22, encompassing every value and subset therebetween. For example, offrom about 1 to about 5, or about 5 to about 10, or about 10 to about15, or about 15 to about 22, encompassing any value and subsettherebetween. In other embodiments, the thiol-based polymer may compriseeven a greater number of thiol functional groups. Each of these valuesis critical to the embodiments of the present disclosure and may dependon a number of factors including, but not limited to, the desireddegradation rate, the desired degradation process, and the like.

The thiol-based polymer may be, but is not limited to, a thiol-enereaction product, a thiol-yne reaction product, a thiol-epoxy reactionproduct, and any combination thereof. The thiol-based polymers, whetherthe reaction product of thiol-ene, thiol-yne, or thiol-epoxy, may bereferred to herein as generally being the reaction product of a thiolfunctional group and an unsaturated functional group, and may be formedby click chemistry. The thiol functional group is an organosulfurcompound that contains a carbon-bonded sulfhydryl, represented by theformula —C—SH or R—SH, where R represents an alkane, alkene, or othercarbon-containing group of atoms.

Thiol-ene reactions may be characterized as the sulfur version of ahydrosilylation reaction. The thiol-ene reaction product may be formedby the reaction of at least one thiol functional group with a variety ofunsaturated functional groups including, but not limited to, amaleimide, an acrylate, a norborene, a carbon-carbon double bond, asilane, a Michael-type nucleophilic addition, and any combinationthereof. As used herein, the term “Michael-type nucleophilic addition,”and grammatical variants thereof, refers to the nucleophilic addition ofa carbanion or another nucleophile to an α,β-unsaturated carbonylcompound, having the general structure (O═C)—C^(α)═C^(β)—. An example ofa suitable thiol-ene reaction product may include, but is not limitedto, 1,3,5,-triacryloylhexahydro-1,3,5-triazine. Examples of suitablethiol-ene/silane reaction products that may be used in forming at leasta portion of the downhole tool 100 (FIG. 1) or component thereofinclude, but are not limited to, the following Formulas 1-6:

In Formula 1, it is to be appreciated that the nitrogen atoms arepositively charged and chlorine atoms are negatively charged.

In Formula 6, it is to be appreciated the sodium atoms are positivelycharged and one oxygen atom on each sulfate group is the negativelycharged counteranion.

The thiol-yne reaction products may be characterized by an organicaddition reaction between a thiol functional group and an alkyne, thealkyne being an unsaturated hydrocarbon having at least onecarbon-carbon triple bond. The addition reaction may be facilitated by aradical initiator or UV irradiation and proceeds through a sulfanylradical species. The reaction may also be amine-mediated, ortransition-metal catalyzed.

The thiol-epoxy reaction products may be prepared by a thiol-enereaction with at least one epoxide functional group. Suitable epoxidefunctional groups may include, but are not limited to, a glycidyl ether,a glycidyl amine, or as part of an aliphatic ring system. Specificexamples of epoxide functional groups may include, but are not limitedto, bisphenol-A diglycidyl ether, triglycidylisocyanurate,trimethylolpropane triglycidyl ether, and any combination thereof. Thethiol-epoxy reaction products may proceed by one or more of themechanisms presented below; however, other mechanisms may also be usedwithout departing from the scope of the present disclosure:

As mentioned above, the thiol-based polymer may comprise at least onethiol functional group and at least one degradable functional group.Such degradable functional groups may include, but are not limited to,one or more of a degradable monomer, a degradable oligomer, or adegradable polymer. Specific examples of degradable functional groupsmay include, but are not limited to, an acrylate, a lactide, a lactone,a glycolide, an anhydride, a lactam, an allyl, a polyethylene glycol, apolyethylene glycol-based hydrogel, an aerogel, a poly(lactide), apoly(glycolic acid), a poly(vinyl alcohol), apoly(N-isopropylacrylamide), a poly(ε-caprolactone, apoly(hydroxybutyrate), a polyanhydride, an aliphatic polycarbonate, anaromatic polycarbonate, a poly(orthoester), a poly(hydroxyl esterether), a poly(orthoester), a poly(amino acid), a poly(ethylene oxide),a polyphosphazene, a poly(phenyllactide), a poly(hydroxybutyrate), adextran, a chitin, a cellulose, a protein, an aliphatic polyester, andany combination thereof.

In some embodiments, the thiol-based polymer comprises at least onepolyethylene glycol-based hydrogel, such as one formed by a four-armpolyethylene glycol norbornene that is crosslinked with dithiolcontaining crosslinkers to form a chemically crosslinked hydrogel toimpart swelling properties. The swelling properties of such a hydrogelmay vary depending on a number of factors including, but not limited to,network density, the degree of crosslinking, and any combinationthereof. In some embodiments, the degree of crosslinking may bedesirably increased in order to achieve a higher tensile modulus andreduced swelling percentage.

In some embodiments, the elastomer forming a portion of the sealingelement 285 (or one or more portions or components of the body 210) orthe sealing element 285 as a whole is formed by a molding process, orpreferably by a casting process. During either one of these processes,the anhydrous acid particles described herein may be added to theelastomer, for example, without departing from the scope of the presentdisclosure (e.g., when the anhydrous acid particles are integral to theelastomer). As described herein, the term “molding,” and grammaticalvariants thereof (e.g., “molding process,” and the like), refers to amanufacturing process in which solid elastomer(s) (and any additionaladditives, if applicable, including the anhydrous acid particlesdescribed herein) is heated into a pliable solid and shaped with a die.The term encompasses dies that produce particular shaped materials, andthose that produce long-continuous shapes (e.g., tubes or cylinders, andthe like). Where the sealing element 285 as a whole is formed using themolding process, the anhydrous acid particles described herein, and anyadditional additives, are formed using the molding process. Moldingtypically requires a molding machine including various parts, such as ahopper, a heater, a reciprocating screw, a mold cavity, a removableplaten, among others. Single molds are made for each desired shape, andare made by technical toolmakers out of a metal (e.g., steel oraluminum) and thereafter precision-machined to form desired features.Molding generally requires high pressure and high velocity injection ofthe heated (or molten) elastomer (and any additional additives, ifapplicable) into the die cavity. Generally, the molding process used forforming a molded elastomer(s) and/or a molded sealing element(s) 285described herein is either an injection molding process, a compressionmolding process, or an extrusion molding process.

As stated above, in some embodiments, the elastomer forming a portion ofthe sealing element 285 or the sealing element 285 as a whole is formedby a casting process, which uses lower curing temperatures thussimplifying addition of the anhydrous acid particles described herein.As used herein, the term “cast,” and grammatical variants thereof (e.g.,“casting,” “casting process,” and the like) refers to a manufacturingprocess in which a mold is filled with a liquid elastomer (and anyadditional additives, if applicable), followed by hardening. Where thesealing element 285 as a whole is formed using the casting process, theanhydrous acid particles described herein, and any additional additives,are added during the casting process. Hardening is a polymerizationprocess meaning that the elastomer(s) are polymerized, typically throughheat, a chemical reaction, and/or irradiation. In many cases, a castelastomer(s) and/or a cast sealing element 285 formed by the castingprocess described herein are considered “thermoset,” meaning that oncehardened, the elastomer or sealing element 285 cannot be heated andmelted to be shaped differently. In other cases, a cast elastomer(s) ora cast sealing element(s) 285 are considered “thermoplastic,” meaningthat once hardened, the cast elastomer(s) or the sealing element(s) 285can be heated and melted to be shaped differently. In some embodiments,a thermoset cast elastomer(s) or a thermoset cast sealing element(s) 285may be for uses in downhole environments, particularly those having hightemperatures to prevent the cast elastomer(s) or the cast sealingelement(s) 285 from softening, melting, or become misshapen.

The casting process for forming the cast elastomer(s) and/or castsealing element(s) 285 described herein is performed by utilizing theliquid phase of the degradable elastomer and a low-cost mold at reducedtemperatures and low pressures, typically atmospheric pressure. Thecasting molds may be flexible and made of low cost materials, such aslatex rubber, room temperature vulcanized silicone rubber, or otherrubbers. Cast molds may also be constructed from metals such as aluminumor steel, or from plastics such as polytetrafluoroethylene (Teflon). Thecast elastomer(s) and/or cast sealing element(s) 285 described hereinmay be formed using gravity casting (i.e., mere use of gravity to fillthe mold), vacuum casting (i.e., pulling a vacuum to fill the mold),pressure casting (i.e., applying a small pressure to compress anybubbles within the resin), and any combination thereof. Vacuum castingmay further be used simply to remove any bubbles or other imperfections,as well as vibration, pressure, or centrifugation.

Typically, the pressure used for forming the cast elastomer(s) and/orthe cast sealing element(s) 285 of the present disclosure may be fromabout 0.1 pounds per square inch (psi) to about 250 psi, encompassingevery value and subset therebetween. One (1) psi is equal to 6894.757pascals. The temperature used for forming the cast materials of thepresent disclosure may be from about 20° C. to about 150° C.,encompassing every value and subset therebetween. Each of these valuesis critical to the embodiments of the present disclosure and may dependon a number of factors including, but not limited to, the type ofelastomer selected, any additives included in the elastomer (e.g.,anhydrous acid particles, thermoplastics, and the like), the downholetool component created (e.g., the sealing element 285 or a component ofthe body 210), and the like, and combinations thereof.

In some embodiments, the elastomer alone or as part of the sealingelement 285 as a whole is formed using the casting process and theselected elastomer is one or more of a polyurethane rubber, apolyester-based polyurethane rubber, a polyether-based polyurethanerubber, a thiol-based polymer, a hyaluronic acid rubber, apolyhydroxybutyrate rubber, a polyester elastomer, a polyester amideelastomer, a polyamide elastomer, a starch-based resin, a polyethyleneterephthalate polymer, a polyester elastomer, an acrylate-based polymer,a polystyrene polymer, a cellulose-based rubber, copolymers thereof,terpolymers thereof, and any combination thereof. In some embodiments,the elastomer alone or as part of the sealing element 285 as a whole isformed using the casting process and the elastomer is one or more of apolyurethane rubber, a polyester-based polyurethane rubber, apolyether-based polyurethane rubber, a hyaluronic acid rubber, apolyhydroxybutyrate rubber, a polyester elastomer, a polystyrenepolymer, a cellulose-based rubber, and any combination thereof. In otherembodiments, the elastomer alone or as part of the sealing element 285as a whole using the casting process is a polyester-based polyurethanerubber.

The elastomers forming a portion of the sealing element 285 includeanhydrous acid particles. That is, the anhydrous acid particles may beintegral (e.g., using the molding or cast process), or otherwiseassociated with the sealing element 285, such as by use of an adhesive,mechanical means, an encapsulating material, and the like. Inembodiments, the anhydrous acid particles are integral with theelastomer, such that the elastomer and the anhydrous acid particlesalone form a complete structure without the use of additional elements,although additional elements may be included and may affect thestructure of the elastomer and anhydrous acid particles. The anhydrousacid particles may be integral to the elastomer and spatially presentanywhere within or along the perimeter of the elastomer. In someembodiments, the anhydrous acid particles are at least partially alongthe perimeter of the elastomer (e.g., along the perimeter of the sealingelement 285), such that the anhydrous acid particles are only covered bya thin layer the elastomer and are hydrolyzed quickly (e.g., as soon asthe then layer of elastomer is degraded) upon contact with an aqueousfluid in a wellbore environment, such as to maximize acceleration of theelastomer. In other embodiments, the anhydrous acid particles areembedded deeper in the structure of the elastomer (e.g., in a middleportion or toward the inner diameter of the sealing element 285, suchthat degradation of the elastomer takes place to some degree prior tohydrolyzing the anhydrous acid particles with an aqueous fluid in thewellbore environment. In yet other embodiments, the outer surface of thesealing element 285 is dusted with the anhydrous acid particles, suchthat they reside on the outer surface of the sealing element 285 withouta layer (thin or otherwise) of elastomer covering the anhydrous acidparticles. This configuration is possible if the sealing element 285 isplaced within the wellbore in the absence of an aqueous fluid, such thatthe anhydrous acid particles will hydrolyze immediately upon contactwith an aqueous fluid in the wellbore environment after it is set.

The anhydrous acid particles forming a portion of the sealing element285 (or a portion of the body 210) react with an aqueous fluid in thewellbore environment, where the aqueous fluid hydrolyzes the anhydrousacid particles. Once hydrolyzed, the anhydrous acid particles form anacid that accelerates degradation of the elastomer and, in some cases,other degradable materials included in the sealing element 285 and/orthe body 210. The amount of acceleration of the elastomer uponhydrolyzing the anhydrous acid particles depends on a number of factorsincluding, but not limited to, the type and amount of anhydrous acidparticles, the type and amount of elastomer, the type and amount ofaqueous fluid contacting the elastomer and/or anhydrous acid particles,the conditions of the wellbore environment (e.g., temperature), and thelike, and any combination thereof.

The anhydrous acid particles are solid particles, although they may beporous; that is, the anhydrous acid particles are not liquid or gaseous.The anhydrous acid particles hydrolyze in an aqueous fluid (e.g., in awellbore environment) to form an acid, and are themselves anhydrouspro-acids. As used herein, the term “pro-acid,” and grammatical variantsthereof, refers to a material that hydrolyzes upon contact with anaqueous fluid to form an acid. Examples of suitable pro-acids for use informing the anhydrous acid particles described herein include, but arenot limited to, an anhydrous ester (e.g., an anhydrous carbonate, ananhydrous phosphate, and the like), an anhydrous lactone, an anhydrousformate, an anhydrous formate ester, an anhydrous acetate, an anhydrouspropionate, an anhydrous butyrate, an anhydrous acrylate, an anhydrousacrylate ester, an anhydrous ethylsuccinate, and any combinationthereof. Specific examples of anhydrous pro-acids for use as theanhydrous acid particles described herein include, but are not limitedto, anhydrous citric acid, anhydrous urea hydrochloride, anhydrousphosphorous pentoxide, anhydrous maleic acid, anhydrous formic acid,anhydrous acetic formic acid, a metal salt (e.g., one that generateshydrochloric acid in the presence of an aqueous fluid, or one thatlowers the pH of an aqueous fluid to initiate degradation), and anycombination thereof.

The anhydrous acid particles, in some embodiments, hydrolyze in thepresence of an aqueous fluid to form an acid including, but not limitedto, a carboxylic acid, a polycarboxylic acid, an amino carboxylic acid,an amino polycarboxylic acid, a mineral acid, an organic acid, and anycombination thereof. Specific acids formed by hydrolyzing the anhydrousacid particles of the present disclosure include, but are not limitedto, citric acid, hydrochloric acid, trichloroacetic acid, perchloricacid, acetic acid, nitric acid, oxalic acid, steric acid, boric acid,maleic acid, phosphoric acid, formic acid, and any combination thereof.In embodiments, the acid formed by hydrolyzing the anhydrous acidparticles of the present disclosure is citric acid.

For example, the anhydrous acid particles can be anhydrous citric acidwhich hydrolyzes to form citric acid monohydrate, or anhydrous ureahydrochloride which hydrolyzes to form hydrochloric acid, or anhydrousphosphoric pentoxide which hydrolyzes to form phosphoric acid, oranhydrous maleic acid which hydrolyzes to form maleic acid, or anhydrousformic acid which hydrolyzes to form formic acid, or anhydrous aceticformic acid which hydrolyzes to form acetic acid and formic acid, andthe like, and any combination thereof.

The anhydrous acid particles of the present disclosure are present in anamount of less than or equal to maximum packing volume in the sealingelement 285. As used herein, the term “maximum packing volume,” andgrammatical variants thereof, means the maximum amount of anhydrous acidparticles included in a sealing element such that the sealing elementretains its functional integrity (prior to hydrolyzing the anhydrousacid particles), which is equivalent to about 74% by volume. In someembodiments, the anhydrous acid particles are present in an amount ofabout 0.5% to about 60% by volume of the sealing element 285,encompassing any value and subset therebetween. For example, theanhydrous acid particles may be present in an amount of about 0.5% toabout 10%, or about 10% to about 20%, or about 20% to about 30%, orabout 30% to about 40%, or about 40% to about 50%, or about 50% to about60%, or about 10% to about 50%, or about 20% to about 40%, each byvolume of the sealing element 285, encompassing any value and subsettherebetween. In some embodiments, the anhydrous acid particles arepresent in an amount of about 2% to about 30% by volume of the sealingelement 285, encompassing any value and subset therebetween. Each ofthese values is critical to the embodiments described herein and dependon a number of factors including, but not limited to, the selectedelastomer(s), the selected anhydrous acid particles, the desired rate ofdegradation of the sealing element 285, the conditions of the wellboreenvironment, and the like, and any combination thereof.

As previously stated, the anhydrous acid particles are solid in form andhave a unit mesh size in the range of about 1 micrometers (μm) to about6500 μm, encompassing any value and subset therebetween. As used herein,the term “unit mesh size,” and grammatical variants thereof, refers to asize of an object (e.g., a particulate) that is able to pass through asquare area having each side thereof equal to a specified numericalvalue. For example, the anhydrous acid particles may have a unit meshsize of about 1 μm to about 500 μm, or about 500 μm to about 1000 μm, orabout 1000 μm to about 2000 μm, or about 2000 μm to about 3000 μm, orabout 3000 μm to about 4000 μm, or about 4000 μm to about 5000 μm, orabout 5000 μm to about 6000 μm, or about 500 μm to about 5500 μm, orabout 1000 μm to about 5000 μm, or about 1500 μm to about 4500 μm, orabout 2000 μm to about 4000 μm, or about 2500 μm to about 3500 μm,encompassing any value and subset therebetween. In some embodiments, theanhydrous acid particles have a unit mesh size in the range of about 50μm to about 1270 μm, encompassing any value and subset therebetween.Each of these values is critical to the embodiments of the presentdisclosure and depend on a number of factors including, but not limitedto, the selected anhydrous acid particles, the size and shape of thesealing element 285 (or any applicable component of the body 210), thedesired degradation rate of the sealing element 285, the formationprocess of the elastomer and/or the sealing element 285, the conditionsof the wellbore environment, and the like, and any combination thereof.Accordingly, the anhydrous acid particles may be in powdered form (i.e.,fine particles having a unit mesh size of less than about 150 μm, orabout 1 μm to about 150 μm), particulate form (i.e., medium particleshaving a unit mesh size of greater than about 150 μm to about 2millimeters (mm)), or granular form (i.e., large particles having a unitmesh size of greater than about 2 mm to about 6.5 mm). Other forms mayadditionally be suitable, without departing from the scope of thepresent disclosure.

The anhydrous acid particles may increase in unit mesh size uponhydrolyzing compared to their unit mesh size in anhydrous form. Thisincrease in size may occur prior to complete hydrolyzation, which mayrender the anhydrous acid particles into a liquid phase. For example, insome instances, the anhydrous acid particles increase in unit mesh sizeby no more than about 1000% of the unit mesh size of the anhydrous acidparticles prior to hydrolyzing in the presence of an aqueous fluid. Asan example, an acrylate elastomer may increase in unit mesh size byabout 1000% its original size upon hydrolyzing. As another specificexample, the selected anhydrous acid particle may be anhydrous citricacid and once hydrated, the size of the anhydrous acid particleincreases by about 7% by volume as the anhydrous citric acid formscitric acid monohydrate. The amount and extent, if any, of size increasewill depend upon the type of anhydrous acid particles, the type ofaqueous fluid contacted therewith, and the like, and any combinationthereof.

The shape of the anhydrous acid particles may be any shape that meetsthe unit mesh size described herein. The shape may additionally beselected based on the particular anhydrous acid particle(s) selected,the particular elastomer(s) selected, the formation process of theelastomer and/or the sealing element 285, the desired degradation rate,and the like, and any combination thereof. Examples of suitable shapesfor the anhydrous acid particles include, but are not limited to,spherical, spheroid, oblate, ovoid, ellipsoid, capsule-shaped,platelet-shaped, cubic-shaped, rectangular-shaped, rod-shaped,ellipse-shaped, cone-shaped, pyramid-shaped, planar-shaped,oblate-shaped, or cylinder-shaped, and any combination thereof.Accordingly, where the anhydrous acid particles are substantiallynon-spherical, the aspect ratio of the material may range such that thematerial is planar to such that it is cubic, octagonal, or any otherconfiguration.

In some embodiments, some or all of the anhydrous acid particles formingthe sealing element 285 (or the body 210) are at least partiallyencapsulated in a second material (e.g., a “sheath”) formed from anencapsulating material capable of protecting or prolonging hydrolyzingthe anhydrous acid particles and, thus, acceleration of the degradationof the sealing element 285. This second material encapsulationadditionally prevents the anhydrous acid particles from interfering withthe curing process of the elastomer and/or the sealing element 285 as awhole. Additionally, the anhydrous acid particles may be singlyencapsulated in an encapsulating material or a plurality (i.e., two ormore) of anhydrous acid particles may be together encapsulated in anencapsulating material. In other embodiments, the sealing element 285(or the body 210 formed from a degradable material) is at leastpartially encapsulated in an encapsulating material to delaydegradation, regardless of whether all or some of the anhydrous acidparticles are also encapsulated in an encapsulating material. That is, asealing element 285, for example, may be composed of anhydrous acidparticles where one or more are encapsulated in an encapsulatingmaterial, and the sealing element 285 as a whole may additionally beoptionally at least partially encapsulated in an encapsulating material.As used herein, the term “at least partially encapsulated” withreference to an encapsulating material, means that at least 50% of anouter surface of a material (e.g., one or more anhydrous acid particlesor a component of a downhole tool (i.e., the sealing element 285 or acomponent of the body 210) is covered with the encapsulating material.

The sheath may also serve to protect the sealing element 285 and/orportion of the body 210 from abrasion within the wellbore 120, orprotect the anhydrous acid particulates during formation of the sealingelement 285 (e.g., by a casting process). The structure of the sheathmay be permeable, frangible, or of a material that is at least partiallyremovable at a desired rate within the wellbore environment. Whateverthe structure, the sheath is designed such that it does not interferewith the ability of the sealing element 285 to form a fluid seal in thewellbore 120, or the body 210 to perform its necessary function. Theencapsulating material forming the sheath may be any material capable ofuse in a downhole environment and, depending on the structure of thesheath may, or may not, be elastic such that it expands, such as whenused to encapsulate the sealing element 285. For example, a frangiblesheath may break as the sealing element 285 expands to form a fluidseal, whereas a permeable sheath may remain in place on the sealingelement 285 as it forms the fluid seal. As used herein, the term“permeable” refers to a structure that permits fluids (including liquidsand gases) therethrough and is not limited to any particularconfiguration.

The encapsulating material forming the sheath may be of any materialthat the sealing element 285 or body 210 itself may be made of, asdescribed above and below herein, including the elastomers of thepresent disclosure, whether including one or more additives, includingthe anhydrous acid particles. For example, the sheath may be made of adegradable material that degrades faster than the elastomer forming aportion of the sealing element 285. Other suitable encapsulatingmaterials include, but are not limited to, a wax, a drying oil, apolyurethane, a crosslinked partially hydrolyzed polyacrylic, a silicatematerial, a glass material, an inorganic durable material, a polymer, aplastic, a polylactic acid, a polyvinyl alcohol, a polyvinylidenechloride, latex, and any combination thereof.

In some embodiments, the elastomer forming a portion of the sealingelement 285 and/or the body 210 further includes an additive singly orin addition to the anhydrous acid particles (e.g., depending on theparticular component of the downhole tool). In some embodiments, theadditive is a solid oxidizing agent, which facilitates degradation ofthe elastomer. The solid oxidizing agent hydrolyzes in the presence ofan aqueous fluid (e.g., in the wellbore environment) to form anoxidizing liquid. Examples of suitable oxidizing agents include, but arenot limited to, a chlorate, a perchlorate (e.g., ammonium perchlorate),a chlorite, a peroxide, a nitrate (e.g., potassium nitrate), a nitrite,a persulfate (e.g., ammonium persulfate, sodium persulfate, and thelike), and any combination thereof. The oxidizing agents are solid inform and may be any of the unit mesh sizes described above withreference to the anhydrous acid particles. An oxidizing agent mayadditionally be included in other degradable materials described herein,where appropriate, without departing from the scope of the presentdisclosure.

In some embodiments, the elastomer forming a portion of the sealingelement 285 and/or body 210 may have a thermoplastic polymer embeddedadditive therein. The thermoplastic polymer additive may modify thestrength, resiliency, or modulus of the elastomer. It may also aid incontrolling the degradation rate of the sealing element 285 and/or body210, alone or in addition to the anhydrous acid particles, whereincluded. Suitable thermoplastic polymers may include, but are notlimited to, polypropylene, an aliphatic polyester (e.g., polyglycolicacid, polylactic acid, polycaprolactone, polyhydroxyalkanoate,polyhydroxyalkanoiate, polyhydroxybutyrate, polyethylene adipate,polybutylene succinate, poly(lactic-co-glycolic) acid,poly(3-hydroxybutyrate-co-3-hydroxyvalerate), and any combinationthereof. The amount of thermoplastic polymer that may be embedded in theelastomer forming the sealing element 285 and/or body 210 may be anyamount that confers a desirable elasticity without compromising thedesired amount of degradation. In some embodiments, the thermoplasticpolymer may be included in an amount of from about 1% to about 91% byweight of the elastomer, encompassing any value or subset therebetween.For example, the thermoplastic polymer may be included in an amount offrom about 1% to about 30%, or about 30% to about 60%, or about 60% toabout 91% by weight of the elastomer, encompassing any value and subsettherebetween. Each value is critical to the embodiments of the presentdisclosure and depends on a number of factors including, but not limitedto, the desired elasticity, the desired degradability, the portion ofthe downhole tool 100 (FIG. 1) comprising the elastomer, the presence ofother additives (including the anhydrous acid particles), and the like,and any combination thereof.

A reinforcing agent additive may additionally be included in theelastomer, which may increase the strength, stiffness, or salt creepresistance of the sealing element 285 and/or portion of the body 210comprising the elastomer. Such reinforcing agent additives include, butare not limited to, a particulate, a fiber, a fiber weaver, and anycombination thereof.

The particulate may be of any size suitable for embedding in theelastomer, such as a unit mesh size from about 37 μm to about 400 μm,encompassing any value or subset therebetween. For example, theparticulate may have a unit mesh size from about 37 μm to 150 μm, orabout 150 μm to about 300 μm, or about 300 μm to about 400 μm,encompassing any value and subset therebetween. Moreover, there is noneed for the particulates to be sieved or screened to a particular orspecific particle mesh size or particular particle size distribution,but rather a wide or broad particle size distribution can be used,although a narrow particle size distribution is also suitable. Theparticulate reinforcing agent additives may be any shape provided thatthey meet the desired unit mesh size, including those shapes discussedherein with reference to the anhydrous acid additives.

Particulates suitable for use as reinforcing agent additives in theembodiments described herein may comprise any material suitable for usein the elastomer that provides one or more of stiffness, strength, orcreep resistance, or any other added benefit. Suitable materials forthese particulates include, but are not limited to, organophilic clay,silica flour, metal oxide, sand, bauxite, ceramic materials, glassmaterials, polymer materials (e.g., ethylene vinyl acetate or compositematerials), polytetrafluoroethylene materials, nut shell pieces, curedresinous particulates comprising nut shell pieces, seed shell pieces,cured resinous particulates comprising seed shell pieces, fruit pitpieces, cured resinous particulates comprising fruit pit pieces, wood,composite particulates, and combinations thereof. Suitable compositeparticulates may comprise a binder and a filler material whereinsuitable filler materials include silica, alumina, fumed carbon, carbonblack, graphite, mica, titanium dioxide, barite, meta-silicate, calciumsilicate, kaolin, talc, zirconia, boron, fly ash, hollow glassmicrospheres, solid glass, and combinations thereof.

The fibers for use as reinforcing agent additives in the elastomerdescribed herein may be of any size and material capable of beingincluded therein. In some embodiments, the fibers may have a length ofless than about 3.175 centimeters (cm) (equivalent to 1.25 inches) and awidth of less than about 0.0254 cm (equivalent to 0.01 inches). In someembodiments, a mixture of different sizes of fibers may be used.Suitable fibers may be formed from any material suitable for use as aparticulate, as described previously, as well as materials including,but not limited to, carbon fibers, carbon nanotubes, graphene,fullerene, a ceramic fiber, a plastic fiber, a glass fiber, a metalfiber, and any combination thereof. In some embodiments, the fibers maybe woven together to form a fiber weave for use in the elastomer.

In some embodiments, the reinforcing agent additive may be included inthe elastomer in an amount of from about 1% to about 91% by weight ofthe elastomer, encompassing any value or subset therebetween. Forexample, reinforcing agent may be included in an amount of from about 1%to about 30%, or about 30% to about 60%, or about 60% to about 91% byweight of the elastomer, encompassing any value and subset therebetween.Each of these values is critical to the embodiments of the presentdisclosure and depends on a number of factors including, but not limitedto, the desired stiffness of the elastomer, the desired strength of theelastomer, the desired salt creep resistance of the elastomer, the typeof elastomer selected, the type of downhole tool having the elastomerincluded therein, the type and amount of other additives (including theanhydrous acid particles), and the like, and any combination thereof.

In some embodiments, the body 210, or a component thereof or a portionof a component thereof, may also be composed of the elastomers describedherein, which may or may not include the anhydrous acid particles, oranother degradable material type. However, unlike the sealing element285, the body 210 (and most components thereof, e.g., slips, wedges,ball(s), and the like as previously described) is sufficiently rigid toprovide structural integrity to the downhole tool, or frac plug 200. Thebody 210 may degrade in the wellbore environment such as when exposed toone or more of the stimuli capable of degrading the elastomers describedabove, including an aqueous fluid, an acid (e.g., formed fromhydrolyzing the anhydrous acid particles), an elevated wellboretemperature, and the like. The aqueous fluid may be any aqueous fluidpresent in the wellbore environment including, but not limited to, thoselisted above. The body 210 may thermally degrade in a wellboreenvironment having temperatures greater than about 75° C. (or about 165°F.). The body 210 may also degrade upon contact with a hydrocarbon fluidin the wellbore environment. In such cases, the hydrocarbon fluid mayinclude, but is not limited to, alkanes, olefins, aromatic organiccompounds, cyclic alkanes, paraffins, diesel fluids, mineral oils,desulfurized hydrogenated kerosenes, and any combination thereof.

Accordingly, in some embodiments, the sealing element 285 is composed ofthe elastomer and anhydrous acid particles, and one or more componentsof the body 210 in contact with the sealing element 285 (e.g., a slip, awedge, and the like) is also composed of a degradable material. Suchcontact may include a physical connection or attachment. In addition tothe elastomers described herein, with or without the anhydrous acidparticles, other suitable materials for forming the one or morecomponents of the body 210 may include, but are not limited to, apolysaccharide, chitin, chitosan, a protein, an aliphatic polyester,poly(ε-caprolactone), a poly(hydroxybutyrate), poly(ethyleneoxide),poly(phenyllactide), a poly(amino acid), a poly(orthoester),polyphosphazene, a polylactide, a polyglycolide, a poly(anhydride)(e.g., poly(adipic anhydride), poly(suberic anhydride), poly(sebacicanhydride), poly(dodecanedioic anhydride), poly(maleic anhydride), andpoly(benzoic anhydride), and the like), a polyepichlorohydrin, acopolymer of ethylene oxide/polyepichlorohydrin, a terpolymer ofepichlorohydrin/ethylene oxide/allyl glycidyl ether, and any combinationthereof. Suitable materials for forming one or more components of thebody 210 may also include, but are not limited to, metals or metalalloys that include magnesium, aluminum, iron, nickel, copper, gallium,zinc, zirconium, and the like, and any combination thereof. Combinationsof the foregoing polymers and metals/metal alloys may be used in formingthe body 210.

In some embodiments, hydrolyzing the anhydrous acid particles forming aportion of the sealing element 285 (and where applicable included in oneor more components of the body 210) aid in accelerating degradation ofboth the sealing element 285 and any degradable component of the body210. That is, the anhydrous acid particles hydrolyze to generate acidsthat not only accelerate degradation of the elastomers described herein,but also are capable of accelerative degradable metals and metal alloys(e.g., magnesium or aluminum metal and metal alloys, and the like). Insome embodiments, independent of the anhydrous acid particles, the body210 and/or the sealing element 285 releases a degradation accelerantthat is not formed from hydrolyzing an anhydrous acid particle(s) toaccelerate degradation of one or both of the body 210 and/or the sealingelement 285. For example, the accelerant may be a natural component thatis released upon degradation of either the body 210 or the sealingelement 285, such as an acid (e.g., release of an acid upon degradationof the body 210 formed from a polylactide). Similarly, the body 210 mayrelease a base that would aid in degrading the sealing element 285, suchas, for example, if the body 210 were composed of a galvanicallyreacting material. In other cases, the accelerant may be embedded in thematerial forming either or both of the body 210 and the sealing element285 (e.g., the elastomer). The accelerant may be in any form, includinga solid or a liquid. In other embodiments, the accelerant can be anatural byproduct of the degradation of the material and is notspecifically added to act as an accelerant.

Suitable accelerants may include, but are not limited to, a crosslinker,sulfur, a sulfur releasing agent, a peroxide, a peroxide releasingagent, a catalyst, an acid, an acid releasing agent other than theanhydrous acid particles described herein, a base, a base releasingagent, and any combination thereof. In some embodiments, the accelerantmay cause the body 210 or the sealing element 285 to become brittle toaid in degradation. Specific accelerants may include, but are notlimited to, a polylactide, a polyglycolide, an ester, a cyclic ester, adiester, a lactone, an amide, an alkali metal alkoxide, a carbonate, abicarbonate, an alcohol, an alkali metal hydroxide, ammonium hydroxide,sodium hydroxide, potassium hydroxide, an amine, an alkanol amine, aninorganic acid or precursor thereof (e.g., hydrochloric acid,hydrofluoric acid, ammonium bifluoride, and the like), an organic acidor precursor thereof (e.g., formic acid, acetic acid, lactic acid,glycolic acid, aminopolycarboxylic acid, polyaminopolycarboxylic acid,and the like), and any combination thereof. As an example, thedegradation of an elastomer described herein (e.g., forming all or aportion of the sealing element 285) can produce adipic acid, succinicacid, or isophthalic acid during its degradation, and the released acidwill lower the pH of a wellbore fluid (introduced or naturallyoccurring, such as produced wellbore fluids) and accelerate thedegradation of an aluminum alloy or magnesium alloy forming all or aportion of the body 210.

The accelerant, when embedded in the body 210 or the sealing element285, may be present in the range of from about 0.01% to about 25% byweight of the body 210 or the sealing element 285 (including theanhydrous acid particles) (in addition to the anhydrous acid particles),encompassing any value and subset therebetween. For example, theaccelerant may be present of from about 0.01% to about 5%, or about 5%to about 10%, or about 10% to about 25% by weight of the body 210 or thesealing element 285 (including the anhydrous acid particles),encompassing any value and subset therebetween. Each of these values iscritical to the embodiments of the present disclosure and may depend ona number of factors including, but not limited to, the material formingthe body 210, the elastomer forming a portion of the sealing element285, the type and amount of anhydrous acid particles forming a portionof the sealing element 285, the desired degradation rate of the body 210and/or the sealing element 285, and the like, and any combinationthereof.

Each of the individual components forming the body 210 and the sealingelement 285 (i.e., the elastomer, the anhydrous acid particles, and anyadditional additives) is preferably present in the body 210 and thesealing element 285 uniformly (i.e., distributed uniformly throughout).The choices and relative amounts of each component are adjusted for theparticular downhole operation (e.g., fracturing, workover, and the like)and the desired degradation rate (i.e., accelerated, rapid, or normal)of the body 210 and/or sealing element 285. Factors that may affect theselection and amount of components may include, for example, thetemperature of the subterranean formation in which the downholeoperation is being performed, the expected amount of degradationstimulant (e.g., aqueous fluid) in the wellbore environment, the amountof elasticity required for the sealing element 285 (e.g., based onwellbore diameter, for example), the duration of the downhole operation,and the like, and any combination thereof.

Referring again to FIG. 2, in operation the frac plug 200 may be used ina downhole fracturing operation to isolate a zone of the formation 115below the frac plug 200. Referring now to FIG. 4, with continuedreference to FIG. 2, the frac plug 200 is shown disposed betweenproducing zone A and producing zone B in formation 115. In aconventional fracturing operation, before, after, or in conjunction withsetting the frac plug 200 to isolate zone A from zone B, a plurality ofperforations 400 are made by a perforating tool (not shown) through thecasing 125 and cement 127 to extend into producing zone A. Then a wellstimulation fluid is introduced into the wellbore 120, such as bylowering a tool (not shown) into the wellbore 120 for discharging thefluid at a relatively high pressure or by pumping the fluid directlyfrom the derrick 112 (FIG. 1) into the wellbore 120. The wellstimulation fluid passes through the perforations 400 into producingzone A of the formation 115 for stimulating the recovery of fluids inthe form of oil and gas containing hydrocarbons. These production fluidspass from zone A, through the perforations 400, and up the wellbore 120for recovery at the surface 105 (FIG. 1).

The frac plug 200 is then lowered by the tool string 118 (FIG. 1) to thedesired depth within the wellbore 120, and the sealing element 285 (FIG.2) is set against the casing 125, thereby isolating zone A as depictedin FIG. 4. Due to the design of the frac plug 200, the flowbore 205(FIG. 2) of the frac plug 200 allows fluid from isolated zone A to flowupwardly through the frac plug 200 while preventing flow downwardly intothe isolated zone A. Accordingly, the production fluids from zone Acontinue to pass through the perforations 400, into the wellbore 120,and upwardly through the flowbore 205 of the frac plug 200, beforeflowing into the wellbore 120 above the frac plug 200 for recovery atthe surface 105.

After the frac plug 200 is set into position, as shown in FIG. 4, asecond set of perforations 410 may then be formed through the casing 125and cement 127 adjacent intermediate producing zone B of the formation115. Zone B is then treated with well stimulation fluid, causing therecovered fluids from zone B to pass through the perforations 410 intothe wellbore 120. In this area of the wellbore 120 above the frac plug200, the recovered fluids from zone B will mix with the recovered fluidsfrom zone A before flowing upwardly within the wellbore 120 for recoveryat the surface 105.

If additional fracturing operations will be performed, such asrecovering hydrocarbons from zone C, additional frac plugs 200 may beinstalled within the wellbore 120 to isolate each zone of the formation115. Each frac plug 200 allows fluid to flow upwardly therethrough fromthe lowermost zone A to the uppermost zone C of the formation 115, butpressurized fluid cannot flow downwardly through the frac plug 200.

After the fluid recovery operations are complete, the frac plug 200 mustbe removed from the wellbore 120. In this context, as stated above, atleast a portion of the sealing element 285 and/or body 210 (FIG. 2) ofthe frac plug 200 may degrade by exposure to the wellbore environment.For example, the sealing element 285 and/or the body 210 may degradeupon prolonged contact with fluids present naturally or introduced inthe wellbore 120, or other conditions in the wellbore 120. Othercombinations of degradability are suitable, without departing from thescope of the present disclosure, as discussed above, for example.

Accordingly, in an embodiment, the frac plug 200 is designed todecompose over time while operating in a wellbore environment, therebyeliminating the need to mill or drill the frac plug 200 out of thewellbore 120. Thus, by exposing the frac plug 200 to the wellboreenvironment, at least some of its components will decompose, causing thefrac plug 200 to lose structural and/or functional integrity and releasefrom the casing 125. The remaining components of the frac plug 200 willsimply fall to the bottom of the wellbore 120. In various alternateembodiments, degrading one or more components of a downhole tool 100performs an actuation function, opens a passage, releases a retainedmember, or otherwise changes the operating mode of the downhole tool100. Also, as described above, the material or components embeddedtherein for forming the body 210 and sealing element 285 of the fracplug 200, as well as the use of the optional sheath, may be selected tocontrol the decomposition rate of the frac plug 200.

Referring again to FIG. 1, removing the downhole tool 100 from itsattachment in the wellbore 120 is more cost effective and less timeconsuming than removing conventional downhole tools, which requiremaking one or more trips into the wellbore 120 with a mill or drill togradually grind or cut the tool away. Instead, the downhole tools 100described herein are removable by simply exposing the tools 100 to anaturally occurring or standard downhole environment (e.g., fluidspresent in a standard downhole operation, temperature, pressures,salinity, and the like) over time. The foregoing descriptions ofspecific embodiments of the downhole tool 100, and the systems andmethods for removing the downhole tool 100 from the wellbore 120 havebeen presented for purposes of illustration and description and are notintended to be exhaustive or to limit this disclosure to the preciseforms disclosed. Many other modifications and variations are possible.In particular, the type of downhole tool 100, or the particularcomponents that make up the downhole tool 100 (e.g., the body andsealing element) may be varied. For example, instead of a frac plug 200(FIG. 2), the downhole tool 100 may comprise a bridge plug, which isdesigned to seal the wellbore 120 and isolate the zones above and belowthe bridge plug, allowing no fluid communication in either direction.Alternatively, the downhole tool 100 could comprise a packer thatincludes a shiftable valve such that the packer may perform like abridge plug to isolate two formation zones, or the shiftable valve maybe opened to enable fluid communication therethrough. Similarly, thedownhole tool 100 could comprise a wiper plug or a cement plug.

While various embodiments have been shown and described herein,modifications may be made by one skilled in the art without departingfrom the scope of the present disclosure. The embodiments described hereare exemplary only, and are not intended to be limiting. Manyvariations, combinations, and modifications of the embodiments disclosedherein are possible and are within the scope of the disclosure.Accordingly, the scope of protection is not limited by the descriptionset out above, but is defined by the claims which follow, that scopeincluding all equivalents of the subject matter of the claims.

To facilitate a better understanding of the embodiments of the presentdisclosure, the following examples of or representative embodiments aregiven. In no way should the following examples be read to limit, or todefine, the scope of the disclosure.

Example 1

In this example, the degradation rate in terms of mechanical integrity(Shore D durometer) of cast polyester-based polyurethane samples having0%, 5%, 10%, 15%, or 25% anhydrous citric acid particles includedtherein during the casting process were evaluated after three (3) daysof incubation in tap water at 150° F. (equivalent to 65.6° C.). As shownin FIG. 5, each of the 5%, 10%, 15%, and 25% anhydrous citricacid-containing particles samples exhibited increased mechanicalintegrity loss compared to the 0% anhydrous citric-acid containingparticles sample. The rate of mechanical loss increased with theincreasing concentration of anhydrous acid particles. Indeed, the 25%anhydrous citric-acid containing particle sample lost almost allmechanical integrity in 2 days, and the 15% anhydrous citric-acidcontaining particle sample lost almost all mechanical integrity in 3days. It is also apparent that the cast polyester-based polyurethanehaving 0% anhydrous acid particles exhibited little to no change in itsmechanical properties during the elapsed time period. FIG. 5 shows theprecise durometer measurements at 0, 1, and 3 days, and a linearregression for each sample type.

Example 2

In this example, the degradation rate in terms of mechanical integrity(Shore D durometer) of cast polyester-based polyurethane samples having0%, 10%, 15%, or 25% anhydrous citric acid particles included thereinduring the casting process were evaluated after five (5) days ofincubation in tap water at 120° F. (equivalent to 48.9° C.). As shown inFIG. 6, after five days, each of the 5%, 10%, 15%, and 25% mechanicalintegrity loss compared to the 0% anhydrous citric-acid containingparticles sample, although at a slower rate than at the highertemperature of Example 1. The rate of mechanical loss increased with theincreasing concentration of anhydrous acid particles. For example, the25% anhydrous citric-acid containing particle sample lost almost allmechanical integrity in 4 days, and the 15% anhydrous citric-acidcontaining particle sample lost almost all mechanical integrity in 5days. It is also apparent that the cast polyester-based polyurethanehaving 0% anhydrous acid particles exhibited little to no change in itsmechanical properties during the elapsed time period. FIG. 6 shows theprecise durometer measurements at 0, 1, and 3 days, and a linearregression for each sample type.

Example 3

In this example, the effect of chelating agents and scale inhibitors wasassessed on the production and distribution of the byproducts from thedissolution of degradable tools. A dissolvable material (DM-200,metallic alloy, Halliburton Energy Services, Inc.) was cut into rods (2inches in length, ½ inch diameter) and placed into the lumen ofpolyvinyl chloride (PVC) tubes (2 inches in length). The mass of each ofthe dissolvable material rods was 12 grams. Five samples were preparedin which the dissolvable material within the PVC tubes was furthercombined with a chelating agent (citric acid), a scale inhibitor (solidpolyphosphate), or both, as outlined in Table 1 below.

TABLE 1 Experimental Samples Sample Citric Acid (g) Scale Inhibitor (g)1 - High Citric Only 12 0 2 - Scale Inhibitor Only 0 6 3 - Medium Mix 63 4 - Low Mix 3 1 5 - Brine Only 0 0

The samples were then placed in a close-fitting pressure vessel, inwhich the samples are in a confined space. This confined space can becompared to a wellbore in which a downhole tool has little room aroundit, and degradation byproducts of the degradable portion of the tool arenot easily able to migrate or move out of the way as they are formed.This configuration maximizes the likelihood of a rock-like degradationbyproduct forming during the dissolution process. The samples were thenexposed to 15% KCl brine at 200° F. for 18 hours.

FIG. 7 shows a photograph of the five rods within the PVC tubes before adissolution experiment was conducted. It can be seen that there is auniform size and shape to each of the samples. After the dissolutionexperiment in KCl brine, the samples were removed and inspected. Theresults of the dissolution show a high degree of variation depending onwhich additives were present. FIG. 8 provides a photograph of the fivesamples after the experiment, in order of Sample 1 on the far left toSample 5 on the far right. Samples 2 and 5, which did not have anychelating agent (citric acid), generating enough internal pressure thatthe surrounding PVC tubes burst open. Sample 4, a low concentrationmixture of chelating agent (citric acid) and scale inhibitor, showssignificant bulging due to an internal pressure, indicating theformation of some rock-like degradation products. Similarly, Sample 1,which contained a high concentration of chelating agent (citric acid),but no scale inhibitor, shows significant bulging, although not aspronounced as the low concentration Sample 4. Sample 5, which containsan intermediate concentration of chelating agent in combination with ascale inhibitor shows no signs of bulging or plugging of the PVC lumen.These results indicate that the combination of a chelating agent and ascale inhibitor are able to control and direct the size, morphology,distribution, and production of degradation byproducts from a degradabletool even in enclosed and limited spaces. The use of a chelating agentor a chelating agent/scale inhibitor mixture reduces the formation ofrock-like degradation byproducts and plugs. Moreover, the degree towhich the distribution and production is controlled is dependent on theconcentration of the chelating agent and the scale inhibitor. A personof ordinary skill in the art will recognize that the optimal dosingconcentration of these agents will depend on a number of factors in acase by case basis, including the degradable material used, thechelating agent used, the scale inhibitor used, temperature, pressure,brine conditions, and time of dissolution.

Therefore, the disclosed systems and methods are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as the teachings of the present disclosure may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered, combined, or modified and all such variations are consideredwithin the scope and spirit of the present disclosure. The systems andmethods illustratively disclosed herein may suitably be practiced in theabsence of any element that is not specifically disclosed herein and/orany optional element disclosed herein. While compositions and methodsare described in terms of “comprising,” “containing,” or “including”various components or steps, the compositions and methods can also“consist essentially of” or “consist of” the various components andsteps. All numbers and ranges disclosed above may vary by some amount.Whenever a numerical range with a lower limit and an upper limit isdisclosed, any number and any included range falling within the range isspecifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b,” or, equivalently, “from approximately a-b”) disclosed herein isto be understood to set forth every number and range encompassed withinthe broader range of values. Also, the terms in the claims have theirplain, ordinary meaning unless otherwise explicitly and clearly definedby the patentee. Moreover, the indefinite articles “a” or “an,” as usedin the claims, are defined herein to mean one or more than one of theelement that it introduces.

1. A downhole tool comprising: i) a body comprising a degradable core;and ii) an anhydrous, partially hydrated, fully hydrated, or solidchelating agent integrated into the downhole tool; wherein upondegradation of the degradable core, the integrated chelating agentreduces consolidation of one or more degradation products of thedegradable core.
 2. The downhole tool of claim 1, wherein the chelatingagent is integrated into the downhole tool as layer around thedegradable core, a liner on an inner diameter of the degradable core, anappendage extending downward from a bottom portion of the downhole tool,as a component of the degradable core, or combinations thereof.
 3. Thedownhole tool of claim 1, wherein the chelating agent is integrated intothe downhole tool as a composition comprising the chelating agent and adegradable binder.
 4. The downhole tool of claim 3, wherein thedegradable binder is selected from the group consisting of a salt, awax, a fusible metal, a polymer, a rubber, and combinations thereof. 5.The downhole tool of claim 1, further comprising a scale inhibitor. 6.The downhole tool of claim 5, wherein the scale inhibitor is integratedwith the chelating agent.
 7. The downhole tool of claim 5, wherein aratio of chelating agent to scale inhibitor is in the range of about 6:1to about 1:1.
 8. The downhole tool of claim 1, wherein the chelatingagent is selected from the group consisting of acetic acid, citric acid,lactic acid, succinic acid, maleic acid, a phosphonate, EDTA, Na2EDTA,HEDTA, DTA, NTA, HACA, DTPA, HEIDA, polyasparctic acid, methylglycinediacetic acid (MGDA), N-tris[(1,2-dicarboxyethoxy)ethyl]amine (TCA6),N-bis[2-(carboxymethoxy)ethyl]glycine (BCA3),N-bis[2-(1,2-dicarboxyethoxy)ethyl]glycine (BCA5),N-bis[2-(1,2-dicarboxyethoxy)ethyl]aspartic acid (BCA6),N-bis[2-(methylcarboxymethoxy)ethyl]glycine (MBCA3),N-bis[2-(1,2-dicarboxyethoxy)ethyl]methylglycine (MBCA5), Beta-Alaninediacetic acid (B-ADA), ethylenediaminedisuccinic acid (EDDS) glutamicacid diacetic acid (GLDA), hydroxyiminodisuccinic acid (HIDS),hydroxyethylenediaminetriacetic acid, and combinations thereof.
 9. Thedownhole tool of claim 5, wherein the scale inhibitor is selected fromthe group consisting of NTMP, EDTMP, and DTMP.
 10. The downhole tool ofclaim 1, further comprising: at least one sealing element composed of anelastomer and anhydrous acid particles, wherein at least a portion ofthe sealing element hydrolytically degrades in a wellbore environment,and wherein the anhydrous acid particles are pro-acids.
 11. The downholetool of claim 10, wherein the anhydrous acid particles react with anaqueous fluid in the wellbore environment to form an acid selected fromthe group consisting of a carboxylic acid, a polycarboxylic acid, anamino carboxylic acid, an amino polycarboxylic acid, a mineral acid, anorganic acid, and any combination thereof.
 12. The downhole tool ofclaim 11, wherein the elastomer is selected from the group consisting ofa polyurethane rubber, a polyester-based polyurethane rubber, apolyether-based polyurethane rubber, a thiol-based rubber, a hyaluronicacid rubber, a polyhydroxobutyrate rubber, a polyester elastomer, apolyester amide elastomer, a polyamide elastomer, a starch-based resin,a polyethylene terephthalate polymer, a polybutylene terephthalatepolymer, a polybutylene terephthalate polymer, a polylactic acidpolymer, a polybutylene succinate polymer, a polybutylene succinatepolymer, an acrylate-based polymer, a blend of chlorobutadienerubber/reactive clay/crosslinked sodium polyacrylate, a polystyrenepolymer, a cellulose-based rubber, a polyethylene glycol-based hydrogel,a silicone-based hydrogel, a polyacrylamide-based hydrogel, apolymacon-based hydrogel, copolymers thereof, terpolymers thereof, andany combination thereof.
 13. A method comprising: installing a downholetool in a wellbore, the downhole tool comprising: i) a body comprising adegradable core; and ii) an anhydrous, partially hydrated, fullyhydrated, or solid chelating agent integrated into the downhole tool;fluidly sealing two sections of the wellbore with the downhole tool;performing a downhole operation; exposing at least a portion of thedegradable core to an aqueous fluid in the wellbore environment; andhydrolytically degrading at least a portion of the degradable core inthe wellbore environment, wherein upon the integrated chelating agentreduces consolidation of one or more degradation products of thedegradable core.
 14. The method of claim 13, wherein the chelating agentis integrated into the downhole tool as layer around the degradablecore, a liner on an inner diameter of the degradable core, an appendageextending downward from a bottom portion of the downhole tool, as acomponent of the degradable core, or combinations thereof.
 15. Themethod of claim 13, wherein the chelating agent is integrated into thedownhole tool as a composition comprising the chelating agent and adegradable binder selected from the group consisting of a salt, a wax, afusible metal, a polymer, a rubber, and combinations thereof.
 16. Themethod of claim 13, further comprising a scale inhibitor.
 17. The methodof claim 16, wherein the scale inhibitor is integrated with thechelating agent.
 18. The method of claim 16, wherein a ratio ofchelating agent to scale inhibitor is in the range of about 6:1 to about1:1.
 19. The method of claim 13, wherein the chelating agent is selectedfrom the group consisting of acetic acid, citric acid, lactic acid,succinic acid, maleic acid, a phosphonate, EDTA, Na2EDTA, HEDTA, DTA,NTA, HACA, DTPA, HEIDA, polyasparctic acid, methylglycine diacetic acid(MGDA), N-tris[(1,2-dicarboxyethoxy)ethyl]amine (TCA6),N-bis[2-(carboxymethoxy)ethyl]glycine (BCA3),N-bis[2-(1,2-dicarboxyethoxy)ethyl]glycine (BCA5),N-bis[2-(1,2-dicarboxyethoxy)ethyl]aspartic acid (BCA6),N-bis[2-(methylcarboxymethoxy)ethyl]glycine (MBCA3),N-bis[2-(1,2-dicarboxyethoxy)ethyl]methylglycine (MBCA5), Beta-Alaninediacetic acid (B-ADA), ethylenediaminedisuccinic acid (EDDS) glutamicacid diacetic acid (GLDA), hydroxyiminodisuccinic acid (HIDS),hydroxyethylenediaminetriacetic acid, and combinations thereof.
 20. Themethod of claim 16, wherein the scale inhibitor is selected from thegroup consisting of NTMP, EDTMP, and DTPMP.